Artificial Lift: Adapting to Change

In this first part of a two-part series, we look at how the artificial-lift sector has adapted to producing unconventional resources. The second part of the series to publish in November will crack open the lift toolbox to take a deeper look at the techniques and technologies under development or new to the market.

An Oil Industry worker stands in front of a pumpjack.
The dynamic nature of artificial lift keeps operators and technology developers on a continual quest for solutions to address the gaps.
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Humans and oil are alike in that the inner will to move from a comfortable spot—be it a sofa or a shale pore—often requires the application of outer motivation. It could be the hunger pangs prompting a reach for a donut or the pesky roommate—natural gas—lifting the hefty crude bead on its way to the surface in response to a pressure differential.

So, what is a human to do when the oil needs a little extra convincing to leave its sofa?

Artificial lift has long provided the swift kick needed to get and keep oil moving in conventional resources.

Its story in unconventional resources is one of countless hours spent in the field figuring out that what works in one basin may not necessarily work in another and that what works today to economically lift oil to the surface will change over the life of the well.

In this first part of a two-part series, we look at how the artificial-lift sector has adapted to producing unconventional resources. The second part of the series to publish in November will crack open the lift toolbox to take a deeper look at the techniques and technologies under development or new to the market.

Steep Learning Curve

While the life cycle of conventional oil and gas development is well documented, the rush of unconventional wells that kicked off in 2009 brought with it a whole slew of new challenges, like highly tortuous wellbores and solids production, spurring a greater appreciation for the intricacies of field development.

“There was a steep learning curve in the early stages of producing from unconventional reservoirs. As operators continue to develop these reservoirs and push the envelope by drilling longer laterals with more-complex deviation profiles, artificial lift must keep adapting,” said Thomas Anderson, vice president of rod-lift solutions and PCS Ferguson at ChampionX.

“What worked last week needs to be tweaked to perform even better to handle the challenges we’ll face next week. It’s a constant evolution and we’re continually working to evolve our fit-for-purpose technologies, processes, and services to meet tomorrow’s challenges.”

The remarkable growth of the US shale industry over the past 13 years has been, in part, built on the foundation of conventional oil and gas techniques and technologies.

“Existing lift methods have been redefined based on newer production challenges not present in traditional vertical wells. Well geometry, landing depth, tight casing size, longer lateral draining higher production rates, and increased oil/gas rate are just a few of the new challenges in unconventional wells,” said Humberto Machado, global product line director for artificial lift at Weatherford.

“The lesson learned here is the integrated planning and the development of an artificial-lift strategy that allows scalability, rapid deployment, robust and simple to operate, minimal infrastructure, and ability to match decline curve. This requires significant trial-and-error efforts to develop best practices, and operational guidelines to enhance overall system reliability,” he added.

This redefinition, along with a little adaptation, and a whole lot of experimentation has developed a new toolbox unique to its role in the production process.

“Ten years ago, you wouldn’t have seen much gas lift used in the Permian Basin. Old school, traditional methods of lift, like electrical submersible pumps (ESPs) or rod pumps, were used there then. Gas lift, progressing cavity pumps (PCPs), or some of the other traditional methods weren’t used because these types were not as familiar to operators. They went with what they knew,” said Shauna Noonan, 2020 SPE President and senior director international and Gulf of Mexico supply chain and Fellow for Occidental Petroleum.

Noonan attributes industry events like the SPE Artificial Lift Conference and Exhibition (ALCE) and others for bringing greater awareness of the different types of lift systems used across the globe to the industry.

“By bringing all the lift types together, we can learn from one another and have more tools in our toolbox to choose from. We’re starting to see that change, especially in the growth of new wells where we’re picking the right lift method at the time, and not what they knew,” she said.

“It’s an interesting time. All the gas-lift people that used to be in Louisiana working in the Gulf of Mexico are now in Midland,” she added. “Gas lift is one of the fastest-growing lift methods out there, displacing the other types.”

Market data indicate that the global artificial-lift market is on a positive trajectory. It is projected to see an annual increase of 8% through 2025, up from $11 billion in 2022 to $14 billion, according to Richard Spears, vice president of Spears & Associates.

Speaking at the ALCE on 25 August, Spears showed projections that showed a modest year-over-year increase in rod lift and in gas lift, from $2.3 billion in 2022 to $2.6 billion in 2023, and $900 million in 2022 to $1 billion in 2023.

The ESP market will see the greatest growth, from $6 billion in 2022 to $6.7 billion in 2023, according to Spears.

Continuous Evolution

With more than 130,000 shale wells drilled and put on production in the major basins, the industry is now equipped with the data and the knowledge of what will and will not work when it comes to applying artificial-lift technologies.

Longer lateral sections, larger multistage fracturing jobs, and completion techniques to maximize output from shale deposits are examples where efficiencies were obtained since longer laterals are cheaper to drill and complete per foot due to economies of scale, according to Machado.

“However, there are still questions about efficiency in hydrocarbon recovery over time as production rates are highly variable and unpredictable. The initial production rates during the flowback period, higher flowing pressures, increased gas production, scale buildup, and gas slugging flow are examples of new challenges for artificial-lift technologies to produce efficiently,” he said.

Incorporating digital into artificial lift systems has helped operators make significant gains in their understanding of what is happening downhole on unconventional well pads.

“Multiple artificial-lift measurements can occur on a second-to-second basis on these pads. Our latest generation of production optimization software uses physics-based diagnostics and artificial intelligence to monitor, control, and optimize artificially lifted wells,” said Neha Sahdev, vice president of production optimization for ChampionX.

“It not only aggregates and analyzes all the data, but prioritizes problem wells and provides expert recommendations to optimize performance.”

Adopting data to enable data-driven decisions leads to improved efficiencies, reduced risk, more consistent operational performance, and helps operators find the hidden barrels–all of which lower production costs.

“But it’s really hard to derive value from digital technologies if they are not applied in the context of subject matter expertise,” Sahdev said. “Marrying digital tools to expertise is the lynchpin in the process of aggregating data, extracting insights, taking appropriate actions, and ultimately, autonomously controlling the well.”

Autonomous control is the next evolutionary step in well automation and optimization. The software not only recommends actions but closes the control loop by autonomously executing actions based on key production variables, she explained.

“That is the journey we are now on,” she said. “There will be an adoption curve for autonomous control similar to self-driving cars, but the technology has tremendous potential to improve production consistency in unconventional wells.”

Robert Laird, ESP product lead for Baker Hughes, also sees the adoption of digital systems as a key advancement made in the past 10 years.

“The growth in remote monitoring and surveillance, particularly for ESP-installed wells, has been critical. Operators and production engineers are now more familiar and accustomed to producing wells with ESPs, so now they work with their drilling department to ensure the well is drilled for ESP production,” Laird said.

Improved reliability and data acquisition of actuators, downhole gauges, and surface sensors have allowed operators to better monitor the health of the well and associated equipment, he added.

“Better hardware, like ESP controllers and variable speed drives paired with new algorithms, have allowed us to maintain the ESP within specified operating parameters and serve a dual purpose: protecting the system from damage while also maintaining system reliability and performance in a dynamic unconventional environment,” said Laird.

Significant advancements in ESP systems over the past decade have occurred in supply chain and manufacturing availability and process improvements, according to Ryan Rasmussen, vice president and managing director for ChampionX.

“If you go back 20 years, there were only three ESP companies, and each had a dedicated supply chain. That has fundamentally changed. Manufacturing and supply chain expansion in the past 10 years has been crucial in supporting the US shale boom,” he said.

“As the quality of the equipment increased—and the unique production challenges of unconventional wells required high-volume lift types—it drove greater acceptance of ESPs. And an increasing number of manufacturing vendors has reduced the barrier to entry into the market, increasing the number of competitors in the ESP space. “In the past, an operator may have had only two ESP companies from which to choose, depending on geography. Equipment selection often came down to who had inventory available. That is no longer the case.”

Addressing the Gaps

The continued evolution of artificial lift will ensure that output and efficiency also will continue to improve. Machado sees two main areas of improvement in regard to artificial lift and its ability to handle higher rates of liquids and gas.

“High flow in tight casing is the main production challenge when it comes to unconventional wells—trying to flow high production rates through a tight wellbore with 5.5-in. casing and 2⅞-in. tubing. The narrower the casing, there is less space to manage free gas,” he said. “The second challenge is a high gas/oil ratio. It is the greatest enemy of artificial lift systems—except for gas lift—as it reduces the volumetric efficiency and causes gas‑locking.”

For all the advances made in developing the best or optimal approach in artificially lifting an unconventional well, it is its dynamic nature that keeps operators and technology developers on a continual quest for solutions to address the gaps.

“Unconventional wells are extremely dynamic and draw down rapidly. Subsurface conditions can change quickly once production begins. To improve ESP reliability in these environments, customers have hired consultants to monitor wells in real time. I would argue that this approach has yielded only marginal results, especially considering the number of man-hours invested,” said Rasmussen.

“Outcomes will start meaningfully improving when we take some of the human element out of the equation by linking data sources and moving from real-time monitoring to real-time control. There are still technical gaps to fill, but the next shift in ESP reliability is going to come by connecting the data to autonomous control systems.”

Rasmussen noted that while the industry acquires a ton of data for artificial lift operations, it is measuring the same parameters it has measured for years.

“As we get better at using data for real-time control, we are going to find many more operational variables to measure. Downhole and surface gauges are going to play a big part in data acquisition for autonomous control,” he said.

The application of artificial-lift methods to unconventional reservoirs continues the required adaption and experimentation. One of the more significant gaps technology developers will have to address is its role in the energy transition.

“Where we are now versus where we need to be to achieve carbon neutrality? ESPs are one of the largest contributors to carbon emissions in the OFS industry,” said Laird.

He believes the gaps can be bridged, but it will take thinking differently on artificial-lift solutions, including integrated field automation solutions and high-temperature materials for use in downhole electronics.

“Also, technology has facilitated the ability to design more efficient fluid ends and increase power density which leads to improved system efficiency which have a smaller downhole and surface footprint.” he said. “Systems that operate at faster speed are much shorter, lighter, potentially smaller in diameter, and have fewer moving parts. All of these are very favorable to the operator.”

Another significant gap is not technology but is one the industry is struggling with across all sectors: the need for people.

“The industry is seeing a huge population shift. The resident knowledge base is reaching retirement age. With such deep experience and expertise leaving, proper succession planning is needed to ensure that the next generation of engineers taking their place can fill that gap,” said Anderson.

“On the other hand, the positive aspect of this transition is that some of the traditional concepts and philosophies simply do not apply to the new era of unconventional development. The younger generation is open to ideas that can foster innovation and help all of us think outside the box when it comes to solving the problems our customers encounter in these plays.”

Fostering future innovation is becoming more challenging as a generation of experts retires.

“I’m concerned about who the future artificial-lift gurus are going to be, especially those with operational experience,” said Noonan. “Many of the gurus that the next generation should be mentoring under for artificial lift have retired or they’re going to be retiring within the next 5 years. We’re going to miss the boat with them.”

She added that there is “pretty good job security and career path” for a production engineer going through the cycle.

“It doesn’t matter whether oil prices are up or down,” she said. “Operators are still going to want to keep the wells on production. There will always be artificial lift.”